The present invention relates to the application of buoyancy to objects used in large vessel and platform operations.
Vast oil reservoirs have recently been discovered in very deep waters around the world, principally in the Gulf of Mexico, Brazil and West Africa. Water depths for these discoveries range from 1500 ft to nearly 10,000 ft. Conventional offshore oil production methods using a fixed truss type platform are not suitable for these water depths. These platforms become dynamically active (flexible) in these water depths. Stiffening them to avoid excessive and damaging dynamic responses to wave forces is prohibitively expensive.
Deep water oil and gas production has thus turned to new technologies based on floating production systems. These systems come in several forms, but all of them rely on buoyancy for support and some form of a mooring system for lateral restraint against the environmental forces of wind, waves and current.
These floating production systems (FPS) sometimes are used for drilling as well as production. They are also sometimes used for storing oil for offloading to a tanker. This is most common in Brazil and West Africa, but not in Gulf of Mexico as of yet. In the Gulf of Mexico, oil and gas are exported through pipelines to shore.
Drilling, production, and export of hydrocarbons all require some form of vertical conduit through the water column between the sea floor and the FPS. These conduits are usually in the form of pipes which are called “risers.” Typical risers are either vertical (or nearly vertical) pipes held up at the surface by tensioning devices; flexible pipes which are supported at the top and formed in a modified catenary shape to the sea bed; or steel pipe which is also supported at the top and configured in a catenary to the sea bed (Steel Catenary Risers—commonly known as SCRs).
The flexible and SCR type risers may in most cases be directly attached to the floating vessel. Their catenary shapes allow them to comply with the motions of the FPS due to environmental forces. These motions can be as much as 10%-20% of the water depth horizontally, and 10's of ft vertically, depending on the type of vessel, mooring and location.
Top Tensioned risers (TTRs) typically need to have higher tensions than the flexible risers, and the vertical motions of the vessel need to be isolated from the risers. TTRs have significant advantages for production over the other forms of risers, however, because they allow the wells to be drilled directly from the FPS, avoiding an expensive separate floating drilling rig. Also, wellhead control valves placed on board the FPS allow for the wells to be maintained from the FPS. Flexible and SCR type production risers require the wellhead control valves to be placed on the seabed where access and maintenance is expensive. These surface wellhead and subsurface wellhead systems are commonly referred to as “Dry tree” and “Wet Tree” types of production systems, respectively.
Drilling risers must be of the TTR type to allow for drill pipe rotation within the riser.
Export risers may be of either type.
TTR tensioning systems are a technical challenge, especially in very deep water where the required top tensions can be 1000 kips or more. Some types of FPS vessels, e.g. ship shaped hulls, have extreme motions which are too large for TTRS. These types of vessels are only suitable for flexible risers. Other, low heave (vertical motion), FPS designs are suitable for TTRS. This includes Tension Leg Platform (TLP), Semi-submersibles, and Spars, all of which are in service today.
Of these, only the TLP and Spar platforms use TTR production risers. Semi-submersibles use TTRs for drilling risers, but these must be disconnected in extreme weather. Production risers need to be designed to remain connected to the seabed in extreme events, typically the 100 year return period storm. Only very stable vessels are suitable for this.
Early TTR designs employed on semi-submersibles and TLPs used active hydraulic Pensioners to support the risers. FIG. 10 illustrates a TLP riser system 150 with tensioners 160. As tensions and stroke requirements grow, these active tensioners become prohibitively expensive. They also require large deck area, and the loads have to be carried by the FPS structure.
Spar type platforms recently used in the Gulf of Mexico use a passive means for tensioning the risers. These type platforms have a very deep draft with a central shaft, or centerwell, through which the risers pass. Buoyancy cans inside the centerwell provide the top tension for the risers. These cans are more reliable and less costly than active tensioners.
FIGS. 11 and 12 respectively show the arrangement of the risers in two types of spars: the Caisson Spar 200 (cylindrical) and the “Truss” spar 210, respectively. There may be as many as forty production risers passing through a single centerwell. Buoyancy cans 220, typically cylindrical, are located on the risers, and they are separated from each other by a rectangular grid structure referred to as riser guides 230.
These guides are attached to the hull. As the hull moves the risers are deflected horizontally with the guides. However, the risers are tied to the seafloor, hence as the vessel heaves the guides slide up and down relative to the risers (from the viewpoint of a person on the vessel it appears as if the risers are sliding in the guides).
FIG. 13 shows the arrangement for a single spar production riser 300. A wellhead 310 at the sea floor connects the well casing 320 (below the sea floor) to the riser with a special tieback connector 330. The riser, typically 9″-14″ pipe, passes from the tieback connector through the bottom of the spar and into the centerwell. Inside the centerwell the riser passes through a stem pipe 340, or conduit, which goes through the center of the buoyancy cans. This stem extends above the buoyancy cans themselves and supports the platform to which the riser and the surface wellhead are attached. The buoyancy cans need to provide enough buoyancy to support the required top tension in the risers, the weight of the cans and stem, and the weight of the surface wellhead. FIG. 14 illustrates buoyancy cans and guides in a spar centerwell. FIGS. 15 and 16 illustrate a typical buoyancy can design showing an outer shell 240 surrounding the stem 340.
Since the surface wellhead (“dry tree”) move up and down relative to the vessel, flexible jumper lines 400 (FIG. 13) connect the wellhead to a manifold 500 which carries the product to a processing facility to separate water, oil and gas from the well stream.
Spacing between risers is determined by the size of the buoyancy cans. This is an important variable in the design of the spar vessel, since the riser spacing determines the centerwell size which in turn contributes to the size of the entire spar structure. This issue becomes increasingly more critical as production moves to deeper water because the amount of buoyancy required increases with water depth. The challenge is to achieve the buoyancy needed while keeping the length of the cans within the confines of the centerwell, and the diameters to reasonable values.
The efficiency of the buoyancy cans is compromised by several factors, as follows: